Ultra-tight hydrocarbon-bearing formations (e.g., hydrocarbon-bearing resources) may have very low permeability compared to conventional resources. For example, the Bakken formation may be an ultra-tight hydrocarbon-bearing formation. These ultra-tight hydrocarbon-bearing formations are often stimulated using hydraulic fracturing techniques to enhance oil production. Long (or ultra-long) horizontal wells may be used to enhance production from these resources and provide production suitable for commercial production. However, even with these technological enhancements, these resources can be economically marginal and often only recover 5-15% of the original oil-in-place under primary depletion. Therefore, optimizing the development of this resource by optimizing the wellbore spacing and wellbore completions is critical.
Many different methods are currently be used to attempt to optimize wellbore spacing. One common method is the use of downspacing tests. In downspacing tests, varying well spacings are chosen for different pads and production is compared at different spacings to determine the best (optimal) spacing. Downspacing tests, however, can be expensive and time consuming. In addition, such tests may not provide an answer with high certainty and thus the procedure may need to be repeated many times to increase confidence in the result, which further increases costs and time. Downspacing tests may also include under drilling and/or over drilling numerous pads, which may significantly reduce the value of the resource by inefficiently developing it.
Another technique that has been widely adopted is the use of subsurface or surface microseismic arrays to monitor seismic events during the hydraulic fracturing process. Ideally, this technique provides insight into the dimensions of hydraulic fractures, which helps to determine the optimal well spacing. This technique, however, is often suspect for a number of reasons. A first, and foremost, reason is that microseismic predominantly identifies shear events, which may or may not be associated with the growth of hydraulic fractures. Microseismic events are caused by the creation and dilation of fractures but do not necessarily occur where the fracture fluid or even proppants are placed. The stress state in the rocks adjacent to the hydraulic fracture may be altered from its initial state and hence there are plenty of possible explanations for microseismic events (for example, by reactivating pre-existing planes of weakness or micro fractures within the surrounding rock which are not at all hydraulically connected to the well). Therefore there is a huge uncertainty on the hydraulic fracture geometry using microseismic techniques.
A second disadvantage with microseismic is that it requires knowledge of the subsurface, particularly wave velocities in the media, which are typically unknown and have high uncertainty. Finally, the processing methods for microseismic are typically operated by service companies that use veiled algorithms and have uncertain methods. Despite all these uncertainties and the significant cost of running microseismic, the value of understanding wellbore spacing is needed such that this technology has been widely applied in industry. There are also newer seismic approaches under development that utilize advanced proppants (e.g., tracer studies) or advanced imaging and data acquisition techniques (e.g., electromagnetic based imaging techniques). These approaches, however, are still in the research stage and may likely be costly and complex even if commercialized.
Yet another technique used to evaluate wellbore spacing is the use of pressure measurements. Pressure measurements have been done downhole and at the surface. Pressure tests have been performed during production, during shut-ins, and/or during hydraulic fracturing. For ultra-tight systems, pressure tests during production are rarely done, even though pressure tests are the most commonly employed method for conventional systems to evaluate reservoir performance or fracture geometry. The shut-in times and data acquisition times for pressure testing on unconventional reservoirs is often too long to justify pressure testing. When pressure tests are used during hydraulic fracturing processes, typically only hydraulic fracture hits (where fluid from a stimulated well reaches the well where you are monitoring pressure) are looked for during these tests. Looking for hydraulic fracture hits may give some insight into fracture geometry. Looking only at hydraulic (direct) fracture hits may provide some information but it doesn't distinguish between the different underlying processes that could contribute to these fracture hits (i.e., natural fracture networks, faults, or actual hydraulic fracture growth into an adjacent well). Additionally, direct fracture hits only provide a limited amount of information such as providing a single piece of information when fluid actually communicates with an adjacent well at a fixed distance from the stimulated well. The direct fracture pressure method cannot provide any information if the fluids do not reach the wellbore and it cannot provide accurate information about the final length of hydraulic fractures if they pass the wellbore and continue to grow. Moreover, in the case of cemented liners, fluid could readily pass an adjacent well and never register a direct fracture hit.